Method of Producing Hydrocarbon Fluids From Casing

ABSTRACT

A method of producing hydrocarbon fluids from a wellbore. The method comprises providing a wellbore, with the wellbore having been completed with a tubular string along a horizontal section. The tubular string may be a string of production casing, or joints of slotted tubular bodies. The method also includes running a fluid pumping system into the wellbore. The fluid pumping system comprises a sucker rod string, a traveling valve residing at a lower end of the sucker rod string, and a standing valve releasably connected to a lower end of the traveling valve. The method additionally includes landing the standing valve into a seating nipple along the horizontal section of the wellbore, and then releasing the standing valve from the traveling valve while the fluid pumping system is in the wellbore. The method further includes operating a pumping unit at a surface to produce hydrocarbon fluids from the production casing.

STATEMENT OF RELATED APPLICATIONS

This application claims the benefit of U.S. Ser. No. 62/889,101 entitled “Method of Producing Hydrocarbon Fluids From Casing.” That application was filed on Aug. 20, 2019, and is incorporated herein in its entirety by reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

THE NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT

Not applicable.

BACKGROUND OF THE INVENTION

This section is intended to introduce selected aspects of the art, which may be associated with various embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

FIELD OF THE INVENTION

The present disclosure relates to the field of hydrocarbon recovery operations. More specifically, the present invention relates to a method of producing hydrocarbon fluids from a wellbore. Further still, the invention relates to the production of fluids through the production casing without need of production tubing.

DISCUSSION OF TECHNOLOGY

In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. The drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing.

In completing a wellbore, it is common for the drilling company to place a series of casing strings having progressively smaller outer diameters into the wellbore. These include a string of surface casing, at least one intermediate string of casing, and a production casing. The process of drilling and then cementing progressively smaller strings of casing is repeated until the well has reached total depth. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface. The final string of casing, referred to as a production casing, is also typically cemented into place.

To prepare the wellbore for the production of hydrocarbon fluids, a string of tubing is run into the casing. A packer is optionally set at a lower end of the tubing to seal an annular area formed between the tubing and the surrounding strings of casing. The tubing then becomes a string of production pipe through which hydrocarbon fluids flow from the reservoir and up to the surface.

When a hydrocarbon-producing well is first placed on-line, the formation pressure is typically capable of driving produced fluids up the wellbore and to the surface. Liquid fluids will travel up to the surface through the production tubing, primarily in the form of droplets entrained within gas flow. The fluids are received at the wellhead without the assistance of so-called artificial lift equipment.

During the life of the well, the natural reservoir pressure will decrease as gases and liquids are removed from the formation. As the natural downhole pressure of the well decreases, the gas velocity moving up the well drops below a so-called critical flow velocity. In addition, the hydrostatic head of fluids in the wellbore will work against the formation pressure and block the flow of in situ gas into the wellbore. The result is that formation pressure is no longer able, on its own, to force fluids from the formation and up the production tubing in commercially viable quantities.

In response, various remedial measures have been taken by operators. One option is to simply reduce the inner diameter of the production tubing a small amount, thereby increasing pressure differential. Another option is to monitor tubing pressure through the use of pressure gauges and orifice plates at the surface. U.S. Pat. No. 5,636,693 entitled “Gas Well Tubing Flow Rate Control,” issued in 1997, disclosed the use of an orifice plate and a differential pressure controller at the surface for managing natural wellbore flow up more than one flow conduit.

Another technique frequently used by operators is the reciprocation of a downhole pump. Such pumps include a first valve that is attached to the bottom of the tubing string. Such a valve is referred to as a standing valve. Such pumps also include a second valve that is connected to a lower end of a string of sucker rods. Such a valve is referred to as a traveling valve.

In operation, the sucker rods are moved up and down within the production tubing in response to mechanical movement of a pumping unit at the surface. Various types of pumping units are known, with modern pumping units being fitted with rod pump controllers that control pump times and stroke speeds. The sucker rods move the traveling valve through upstrokes and down strokes, where fluids are drawn into the traveling valve on the down stroke, and then lifted up the production tubing on the upstroke. At the same time, the standing valve receives fluids from the surrounding formation during the traveling valve's upstroke, and is sealed in response to fluid pressure during the traveling valve's down stroke.

The rod string, the traveling valve and the seated valve may together be referred to as a “sucker rod pump,” or a “rod-drawn pump.” The sucker rod pump along with the pumping unit at the surface and the production tubing in the wellbore together comprise a fluid pumping system.

As noted, the traveling valve portion of the pump is connected to the end of the sucker rod string. Typically, an upper portion of the traveling valve is threadedly connected to a plunger, which in turn is connected at the lower end of the sucker rod string. At the same time, the standing valve portion of the pump resides along an inner diameter of the production tubing, below the traveling valve. Specifically, the standing valve is connected to a barrel having a seal assembly.

The standing valve is typically installed by attaching it to a running tool at the lower end of the traveling valve. This means that the standing valve portion is run into the wellbore with the traveling valve at the end of the rod string. The standing valve is lowered until it reaches a constriction in the production tubing, known as a seating nipple. Upon reaching a point of frictional engagement with the seating nipple, the weight of the traveling valve and rod string are released from the surface, down onto the standing valve, causing the standing valve to frictionally engage with the seat.

Many wells today are completed with a horizontal section. This means the well will have a vertical section, a horizontal section, and a transitional section there between. The horizontal section may be in excess of one mile in length, and sometimes in excess of two miles in length. In such wells, it is not practical for the operator to place the rod string and valves along the horizontal wellbore section. This is primarily due to the difficulty in running production tubing and a rod string across the transitional section (or heel) of the wellbore. Accordingly, it is standard practice to run the production tubing only down to the bottom of the vertical section (or near the top of the pay zone), or possibly partially down the transitional section. In this way, the rod string may reciprocate the traveling valve without incurring friction against a “dog leg” in the production tubing.

During the first year or two of production, the reservoir pressure will drive production fluids into the horizontal section of the wellbore and up to the level of the rod-drawn valves. However, over time the reservoir pressure will diminish, leaving the liquids along the horizontal section of the well below the level of the production tubing and valves.

Another problem encountered with the standard completion arrangement relates to so-called slug flow. The typical behavior of horizontal wells is to create slugs of fluid, followed by a “blow down” period of gas. During a first phase, the horizontal well is filling with liquid, hopefully up to a level of the pump intake. Since the liquid weighs more than the gas, the gas may become trapped in the horizontal leg, typically at the higher elevation points. Once the traps of gas are filled, it begins to escape, pushing the liquid ahead of it. The gas will “exhaust” fairly quickly, causing a slug of liquids to move towards the pump intake.

When the gas being held back in “high spots” of the horizontal portion of the wellbore begins to expand, it first pushes liquids from the remainder of the horizontal wellbore up into the vertical section where the pump is located. The normal pump-off controller will correctly calculate high pump fillage, and start running the pumping unit incrementally, i.e., with each cycle, faster until reaching its maximum allowed speed which has been pre-set in the algorithm. When the gas arrives, the pump-off controller will correctly calculate poor pump fillage, and decrease speed very rapidly, e.g., with each cycle, as poor pump fillage is detrimental to the mechanical life of the rod pumping system. The controller may drop the pumping speed all the way down to a pre-set minimum pumping speed. The result can be an extreme amount of cycling between maximum and minimum speed set-points for the pump-off controller, never converging on an ideal speed. Even during the first year of production, this cycle may occur as often as every 15 minutes.

The above problems may be reduced if not eliminated by placing the rod string and valves along the horizontal leg. Therefore, a need exists for a procedure by which hydrocarbon fluids may be pumped directly from the horizontal section of a wellbore. Further, a need exists for a method of operating a rod-drawn pump wherein the rod string and connected traveling valve reside at a selected location along the horizontal section of a wellbore.

SUMMARY OF THE INVENTION

A method of producing hydrocarbon fluids from a wellbore is provided herein. In one aspect, the method first comprises providing a wellbore. The wellbore has been completed to have a horizontal leg, with a string of casing having been placed along the horizontal leg.

The casing may be solid joints of production casing that have been perforated. Alternatively, the casing may be slotted tubular bodies. Examples of slotted tubular bodies are joints of sand screen and joints of slotted liner. In any instance, the wellbore is exposed to reservoir fluids and pressure.

The method also includes running a fluid pumping system into the wellbore. The fluid pumping system generally comprises:

a sucker rod string,

a traveling valve residing at a lower end of the sucker rod string, and

a standing valve releasably connected to a lower end of the traveling valve.

The traveling valve and the standing valve are run into the wellbore together at the end of the rod string. The valves are run down the vertical section, across a transitional section, and then into the horizontal leg of the wellbore to a selected location (or “depth”). Beneficially, the standing valve is releasably connected to a lower end of the traveling valve.

The method additionally comprises landing the standing valve into a seating nipple along the horizontal section of the wellbore. Specifically, the seating nipple resides in series along the casing. The seating nipple may be a specially modified seating nipple placed along the casing above the perforations (or above slotted tubular bodies). In this instance, the seating nipple will have a reduced inner diameter so that a standard pump barrel can land in the seating nipple.

The method further includes releasing the traveling valve from the standing valve. This is done while the fluid pumping system is in the wellbore, i.e., without pulling the rod string. Some compressive force is required to be applied to the rod string from the surface to urge the standing valve to release the engagement pin. This may be acquired simply by dropping weight from the surface.

In operation, once the seating nipple is landed, a second compressive force is applied to the rod string, which is transmitted to the traveling valve and to the releasable connection. This causes the releasable connection to open, allowing the rod string and traveling valve to be released from the standing valve.

The method additionally includes mechanically or operatively connecting a top end of the rod string to a polished rod. The polished rod is part of a pumping unit residing at the surface. In this way, the rod string extends from the polished rod, down into the vertical section of the wellbore, across the transitional section, and into the production casing residing along the horizontal section of the wellbore.

It is understood that the operator will manually adjust a location at which a harness and clamps supporting the polished rod is secured to the polished rod itself. This ensures that the traveling valve will be appropriately spaced above the standing valve.

The polished rod is part of a pumping unit which resides at the surface. The pumping unit may be either a mechanical pumping unit such as a so-called rod beam (or sometimes “rocking beam”) unit. Alternatively, the pumping unit may be a linear pumping unit that uses hydraulic fluid or pneumatic fluid to cyclically act against a piston within a cylinder. In either instance, the pumping unit will use clamps and a harness to secure the pumping unit to the polished rod and to produce reciprocating motion of the downhole traveling valve above the standing valve.

Thereafter, the method includes operating the pumping unit at a surface to produce hydrocarbon fluids from the production casing. Operating the pumping unit causes the sucker rod string and connected traveling valve to reciprocate within the wellbore. Note that no production tubing need be placed within the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the present inventions can be better understood, certain illustrations, charts and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1 is a side view of an illustrative wellbore. In this case, the wellbore is completed horizontally. A traveling valve is shown at a lower end of a sucker rod string while a standing valve is schematically shown in the production casing.

FIGS. 2A and 2B represent a single flow chart showing steps for a method of producing hydrocarbon fluids from a wellbore, in one embodiment.

FIG. 3 is a perspective view of standing valve puller as may be used for releasably connecting a traveling valve to a standing valve in a wellbore. In this view, an engagement pin extends into the standing valve puller.

FIG. 4 is a side view of the holding arm component of the standing valve puller of FIG. 3. Here, the arms of the holding arm component have been pivoted into their open position, ready to receive an engagement pin.

FIG. 5 is an exploded view of the standing valve puller of FIG. 1 along with the engagement pin. Internal components of the standing valve puller are now visible in exploded-apart relation.

FIG. 6A is a side view of the standing valve puller and the engagement pin of FIG. 5. The standing valve puller is in its “latched” position, meaning that arms of a holding arm component have pivoted inwardly to engage a stem of the engagement pin.

FIG. 6B is a cross-sectional view of the standing valve puller and the engagement pin, taken across Line B-B of FIG. 6A. The standing valve puller is again in its latched position, enabling the engagement pin to pull the standing valve puller and connected standing valve (not shown) from a wellbore.

FIG. 7A is a perspective view of the standing valve puller of FIG. 5. Components of the standing valve puller are exploded apart. Here, the engagement pin is not shown.

FIG. 7B is a side view of the exploded-apart components of the standing valve puller of FIG. 7A. Of interest, it can be seen that the arms of the holding arm component are independent (not connected) pieces.

FIG. 8 is another cross-sectional view of the standing valve puller of FIG. 5. Here, the standing valve puller is in its latched position.

FIG. 9A is a perspective view of the holding arm component. Here, both arms of the holding arm component are shown, in side-by-side arrangement. The holding arm component is in the latched position.

FIG. 9B is another perspective view of the holding arm component. Here, the arms of the holding arm component are again in their latched position.

FIG. 10 is a side view of the holding arm component of FIG. 9B. Here, the arms of the holding arm component have been pivoted into their open position, ready to receive an engagement pin. An engagement pin is shown above the holding arm component.

FIG. 11A is a cross-sectional view of a wellbore, with a positive displacement pump being run into the horizontal section. A traveling valve and a standing valve are shown representing the positive displacement pump, with an engagement pin and a standing valve puller connecting the two valves.

FIG. 11B is another cross-sectional view of the wellbore of FIG. 11A. The standing valve has been landed into a seating nipple along the production casing.

FIG. 11C shows a compressive force being applied to the standing valve puller, through the traveling valve. The purpose is to cause the latching arms in the standing valve puller to release.

FIG. 11D shows the traveling valve and connected engagement pin having been released from the standing valve puller. The traveling valve has been repositioned in the wellbore above the standing valve.

FIG. 11E shows the traveling valve being lifted within the wellbore by a sucker rod string. Fluid pumping operations have begun.

FIG. 11F shows the traveling valve being lowered within the wellbore by the sucker rod string. This is part of the pump cycle for the positive displacement pump.

FIG. 12 is a cross-sectional view of a wellbore having received a positive displacement pump. In this view, a sand screen is placed below the standing valve, while a modified seating nipple holds the standing valve in place.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

For purposes of the present application, it will be understood that the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Examples of hydrocarbon-containing materials include any form of oil, natural gas, coal, and bitumen that can be used as a fuel or upgraded into a fuel. Hydrocarbons may include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient conditions. Hydrocarbon fluids may include, for example, oil, natural gas, condensate, coal bed methane, shale oil, shale gas, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and fine solids, and combinations of liquids and fine solids.

As used herein, the terms “produced fluids,” “reservoir fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, a hydrocarbon reservoir, a shale formation or an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, oil, natural gas, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).

As used herein, the term “wellbore fluids” means water, hydrocarbon fluids, formation fluids, or any other fluids that may be within a string of production tubing during a production operation.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

The term “subsurface interval” refers to a formation or a portion of a formation wherein formation fluids may reside. The fluids may be, for example, hydrocarbon liquids, hydrocarbon gases, aqueous fluids, or combinations thereof.

The terms “zone” or “zone of interest” refer to a portion of a formation containing hydrocarbons. Sometimes, the terms “target zone,” “pay zone,” or “interval” may be used.

As used herein, the term “formation” refers to any definable subsurface region regardless of size. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation. A formation can refer to a single set of related geologic strata of a specific rock type, or to a set of geologic strata of different rock types that contribute to or are encountered in, for example, without limitation, (i) the creation, generation and/or entrapment of hydrocarbons or minerals, and (ii) the execution of processes used to extract hydrocarbons or minerals from the subsurface.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

The terms “tubular” or “tubular member” refer to any pipe, such as a joint of casing, a portion of a liner, a joint of tubing, a pup joint, or coiled tubing. The terms “production tubing” or “tubing joints” refer to any string of pipe through which reservoir fluids are produced.

DESCRIPTION OF SPECIFIC EMBODIMENTS

FIG. 1 is a side view of a wellbore 100. The wellbore 100 has been formed for the purpose of producing hydrocarbon fluids up to a surface 105 in commercially viable quantities. The wellbore 100 is formed through an earth subsurface 110, and down to a formation 150 where hydrocarbon fluids are found. The formation 150 may be referred to as a “pay zone.”

Production fluids flow into the wellbore 100 through openings provided along the completion. Such openings may be perforations, or optionally, may be formed with sand screens, ICDs, a gravel pack, an open hole, or other completion type. In the illustrative arrangement of FIG. 1, the end completion is shown with slotted liner 180.

Fluids are produced to the surface 105 through the use of a pumping unit 120. The pumping unit 120 is disposed over a well head 125 which receives the produced fluids including hydrocarbon liquids at the surface 105. Typically, the well 100 will produce primarily hydrocarbon fluids that are incompressible at surface conditions, e.g., oil and water, but there will also be compressible hydrocarbon fluids such as methane, ethane and steam. So-called impurities such as hydrogen sulfide and oxygen may also be present which will need to be separated out after production to meet pipeline specifications.

In the example shown in FIG. 1, the pumping unit 120 is a mechanical beam pump. Of course, it is understood that the pumping unit 120 may alternatively be a pneumatic or hydraulic pumping unit. The pumping unit 120 moves a polished rod 122 up and down at the surface 105, through the well head 125. The polished rod 122, in turn, is connected to a rod string 124 that extends down through the earth subsurface 110.

The illustrative wellbore 100 of FIG. 1 has been completed horizontally. This means the wellbore 100 has a vertical section 142 and a horizontal section 146. A transition section 144, sometimes referred to as a heel or a “build section” or a “transitional section” is formed between the vertical 142 and horizontal 146 sections. The horizontal section 146 extends along the pay zone 150, and terminates at a toe 148.

It is observed that advances in drilling technology have enabled oil and gas operators to “kick-off” and steer wellbore trajectories from a generally vertical orientation to a generally horizontal orientation. The horizontal “leg” of wellbores completed in North America now often exceeds a length of one mile, and sometimes two or even three miles. This significantly multiplies the wellbore exposure to the pay zone 150.

It is also noted that horizontal wellbores are frequently formed along the deposition plane of a formation. Formation fracturing operations are then conducted in stages, with fractures generally propagating vertically into the pay zone. The ability to replicate multiple vertical completions along a single horizontal wellbore is what has made the pursuit of hydrocarbon reserves from unconventional reservoirs, and particularly shales, economically viable within relatively recent times.

The wellbore 100 is completed using strings of casing. In the arrangement of FIG. 1, a string of surface casing 128 is shown. In addition, an intermediate casing string 125 is provided. It is understood that most modern well completions may include at least one, and typically two or three, intermediate casing strings 125. Each casing string 128, 125 will have a progressively smaller inner diameter. The casing strings are cemented into place along most, if not all, of the wellbore completion.

The wellbore 100 is also completed with a string of production casing 126. The production casing 126 extends out along the pay zone 150, passing through the transitional section 144 and to the end 148 of the horizontal section 146. The end of the production casing represents the perforated portion or sand screen 180.

It is observed that the wellbore 100 does not include a string of production tubing. Production tubing is a standard part of any fluid pumping system. The production tubing receives the rod string and connected traveling valve. The production tubing also receives and secures a standing valve. The two valves are typically landed in the build section 144, preferably as deep as possible. However, in the current disclosure no production tubing is required. Instead, the rod string 124 reciprocates within the casing strings 128, 125, 126.

Primarily liquids are pumped through the production casing 126 and to the surface 105, and released through line 132. Primarily gas is produced through the production casing 126 and is released through line 134.

At the end of the rod string 124 are two valves. These represent a traveling valve 162 and a standing valve 164. As discussed above, the traveling valve 162 is connected at the end of the rod string 124 (usually by means of a plunger) and moves with the rod string 124, while the standing valve 164 is frictionally and releasably secured to a seating nipple 166 (usually by means of a barrel and circumferential seal member). In the novel disclosure herein, the seating nipple 166 is placed in series with the production casing 126.

In the view of FIG. 1, the valves 162, 164 are placed above a packer 170 and sealed against a surrounding joint of production casing. The packer 170, in turn, is connected to the sand screen 180 and an internal tubular base pipe 175 of. The sand screen 180 (with the base pipe 175) is run into the wellbore 100 ahead of the packer 170. Beneficially, the sand screen 180 filters solids and fines that enter the wellbore 100 with production fluids, directing the filtered production fluids through a central bore 175 of the packer 170 and into the production casing 126.

It is desirable to be able to pump fluids up the wellbore 100 without pulling the rod string 124 and the traveling valve 162. In addition, it is desirable to pump fluids up the casing 126 without the need of production tubing. Accordingly, a novel method of producing hydrocarbon fluids from the casing is provided herein.

FIGS. 2A and 2B represent a single flow chart showing steps for a method 200 of producing fluids from the casing string of a wellbore, in one embodiment. In one aspect, the method 200 first comprises providing a wellbore. This step is shown at Box 210. The wellbore has been completed to have a horizontal leg. A string of production casing has been placed along the horizontal leg.

It is noted that the step of Box 210 for “providing” a wellbore may include a service company contracting to service the wellbore. Alternatively, providing the wellbore may mean that an operator produces from the wellbore and services the wellbore itself.

The method 200 also includes running a string of casing into the wellbore. This is provided at Box 220. The casing may be a string of production casing that uses joints of standard steel pipe. Multiple joints may be threadedly attached, in series, so that the pipe extends thousands of feet along the horizontal section of the wellbore.

Alternatively, the casing may be one or a few short joints of casing, followed by numerous joints of slotted tubular bodies. The slotted tubular bodies may be joints of slotted liner. This is seen at Box 230. Where slotted tubular bodies are placed along the horizontal section, the operator may also run a packer into the wellbore. The packer may be placed in series between the production casing and the slotted tubular bodies. Placement of such a packer is shown at 1230 in FIG. 12.

In one aspect, the packer is run into the wellbore separate from the casing using a working string. The working string is preferably a coiled tubing string. The packer is run down to a selected location along the production casing. The packer is then set within the wellbore, preferably along the lowest joint of production casing. Placement of such a packer is shown at 170 in FIG. 1.

In a more preferred aspect, the packer is threadedly connected to a sand screen or to a production casing joint above the sand screen. The sand screen will have a filter medium around a slotted base pipe. In this instance, the sand screen is run into the wellbore with the production casing, ahead of the packer. Beneficially, the sand screen filters solids and fines that enter the wellbore with production fluids, directing the filtered production fluids through a central bore of the packer and into the production casing above the packer.

In one aspect, the packer is equipped with a J-slot mechanism. The J-slot mechanism allows the packer to be set through a cycling mechanism, wherein the cycling takes place in response to compressive force applied by the working string through pins, or tabs. Preferably, the compressive force is a mechanical force applied by letting the weight down off of the working string. Thus, in one aspect the method 200 includes operating a J-slot mechanism to set the packer in the wellbore. Alternatively, the packer may be set using a wireline.

Once the packer is in place, the working string is disconnected and is pulled from the wellbore. Thus, the method 200 further includes disconnecting the working string from the packer. Additionally, the method 200 includes pulling the working string from the wellbore.

The method 200 next comprises running a fluid pumping system into the wellbore. This is shown in FIG. 2A at Box 240. The pumping system generally comprises:

a sucker rod string,

a traveling valve residing at a lower end of the sucker rod string, and

a standing valve releasably connected to a lower end of the traveling valve.

The traveling valve, the seated valve and the rod string may together be referred to as a “sucker rod pump” or “rod-drawn pump.”

The rod string used in the fluid pumping system may be comprised of steel, at least along the vertical section of the wellbore. However, low-friction fiberglass rods are preferred along the transitional section and the horizontal section of the wellbore.

The traveling valve and the standing valve are run into the wellbore together using a releasable connection. Of interest, the traveling valve and standing valve are run into the horizontal leg of the wellbore to a selected location.

The method 200 also includes landing the standing valve into a seating nipple along the horizontal section of the wellbore. This is provided at Box 250. The seating nipple resides along the production casing. The seating nipple may be modified to accommodate the outer diameter of a standard pump barrel of a standing valve. Alternatively, the pump barrel may be modified to land into a standard seating nipple placed along the production casing. In either instance, the standing valve lands into the production casing rather than into production tubing.

The method 200 additionally comprises releasing the standing valve from the traveling valve. This means operating the releasable connection in order to disconnect the traveling valve from the standing valve. This is provided at Box 260 of FIG. 2B. The step of Box 260 is done while the traveling valve and standing valve are downhole and without pulling the rod string out of the well.

In a preferred embodiment, the releasable connection is a standing valve puller. FIG. 3 is a perspective view of the standing valve puller 300 of the parent application. The standing valve puller 300 is designed to be used to remove a standing valve (such as standing valve 164) from a wellbore 100. This is done by using the rod string 124, the traveling valve 162 and an engagement pin 310, wherein the engagement pin 310 resides at the lower end of the traveling valve 162 . Cyclically pushing the engagement pin 310 into the standing valve puller 300 alternatingly connects and disconnects the engagement pin 310 from the standing valve puller 300. In the present disclosure the standing valve puller 300 is used to release the traveling valve from the standing valve while the valves are downhole.

In operation, the standing valve puller 300 threadedly connects to the standard standing valve 164 using the existing threaded opening at the top of the standing valve 164. The connection is made by hand at the surface before the standing valve 164 is run into the wellbore 100 and seated in the seating nipple 166.

The standing valve puller 300 will remain connected to the standing valve 164 within the wellbore 100 during production. At the same time, the engagement pin 310 remains connected to the bottom of the traveling valve 162 and, accordingly, will cycle with the sucker rods 124. The engagement pin 310 provides a “latch and release” arrangement with the standing valve puller 300.

In a preferred embodiment, the standing valve puller 300 is no more than 15 to 24 inches in length, measured from a top 322 (shown in FIG. 4) of a holding arm component 320 to a bottom 384 (shown in FIG. 3) of a threaded end connector. In addition, the standing valve puller 300 will have an outer diameter no greater than the outer diameter of the standing valve 164 itself. For example, the standing valve puller 300 may have an outer diameter (measured across the housings 340/370) of about 2.0 inches, although a slightly larger size could be employed depending on casing I.D. Therefore, the standing valve puller 300 will not create a restriction to either run-in or to normal wellbore operations.

The standing valve puller 300 replaces the traditional threaded connection between the traveling valve 162 and the standing valve. (The traditional arrangement is called a “tap-type puller.”)

FIG. 3 shows an engagement pin 310 latched into the standing valve puller 300. The engagement pin 310 defines an elongated body comprising a proximal (or upper) end 312 and a distal (or lower end) 314. (The distal end 314 is seen in FIG. 4.) Between the proximal end 312 and the distal end 314 is a stem 316. Preferably, the stem 316 is about three inches in length.

In the view of FIG. 3, the engagement pin 310 is seen extending down into the standing valve puller 300. More specifically, a stem 316 has passed through a top of the standing valve puller 300. Applying a downward force onto the engagement pin 310 (applied through the rod string 124) causes the elongated stem 316 to move down into the standing valve puller 300. The standing valve puller 300 is designed in such a way that the downward force will cause arms (shown at 325 in FIG. 4) at the top of the puller 300 to pivot inwardly and to latch onto the stem 316. Beneficially, applying the same downward force to the engagement pin 310 a second time will cause the arms 325 to pivot away from the stem 316 and to release the engagement pin 310 from the standing valve puller 300 (seen in FIG. 10). In this way, a “latch and release” cycle is provided that may be performed quickly and repetitively.

FIG. 4 is a perspective view of a holding arm component 320. In this view, the individual arms 325 have been pivoted outward into their “released” position. An engagement pin 310 is positioned above the holding arm component 320, ready to move down through a central bore of the standing valve puller 300 and to depress a sliding component (shown at 330 of FIG. 5.

It is observed that a lower end 324 of each arm 325 includes a beveled inward surface 329. The beveled inward surface 329 accommodates the pivoting action of the arms 325, permitting the arms 325 to pivot outwardly more fully. At the same time, the beveled surfaces 329 receive the shoulder 314 when the engagement pin 310 is moved downwardly into the standing valve puller 300.

Of interest, through-openings 327 are shown through each of the arms 325. The through-openings 327 represent pivot points and are configured to receive a pivot pin (not shown). The pivot pins reside proximate a top of the top housing 340 of the puller 300. The horizontal pins allow the arms 325 to pivot inwardly and outwardly relative to the top housing 340.

The proximal end 312 of the engagement pin 310 comprises a somewhat tubular body 318. The body 318 serves as a box connector, meaning it offers female threads 315 within an opening. The body 318 threadedly connects to the lower end of a running string, such as coiled tubing or a sucker rod string. More preferably, the body 318 threadedly connects to the lower end of the traveling valve 162. In this way, the operator can use the existing rod string 124 and connected traveling valve 162 to engage the standing valve 164. Upon latching into the standing valve puller 300, an upward force is applied to the rod string 124 in order to unseat the standing valve 164. Again, this may be done without removing the rod string 124 from the wellbore 100 beforehand.

Returning back to FIG. 3, additional features of the standing valve puller 300 are seen. These include the top housing 340 and the bottom housing 370. One or more holes 346 are drilled into the top housing 340. Similarly, holes 376 are formed in the bottom housing 370. These are drain holes that allow fluids to drain from the standing valve puller 300 as the standing valve 364 is being pulled from the wellbore 300.

When it is desirable to remove the standing valve 364, such as for maintenance, repair or replacement, the operator will use the standing valve puller 300 to latch onto the engagement pin 310 below the traveling valve 362. Specifically, the shoulder 314 will catch on the arms 325 of the holding arm component 320. The shoulder 314 will hit flanges at a proximal end 322 of the holding arms 320 when in their latched position. The operator will then pull the standing valve puller 300 and connected standing valve 364 from the wellbore 100 together. Thus, the standing valve puller 300 is configured to allow retrieval of the known standing valve 164 from the casing 128 using the traveling valve 162 itself, thereby saving a trip.

Moving now to FIG. 5, FIG. 5 offers an exploded view of the standing valve puller 300 of FIG. 3. Internal components of the standing valve puller 300 are now visible. These include the holding arm component 320, a sliding component 330, the top housing 340, a twisting component 350, a spring 360, the bottom housing 370 and the threaded connector 380.

Along with the standing valve puller 300 and its components, FIG. 5 shows the engagement pin 310 in its entire length. In FIG. 5, the distal end 314 is now seen. The distal end 314 defines a shoulder. When the engagement pin 310 is pulled by the operator from the surface, the shoulder 314 will catch on the arms 325 of the holding arm component 320. More specifically, the shoulder 314 will hit flanges 322 of the holding arms 320 when in their latched position. This is more readily seen in the side view of FIG. 6A, discussed below.

Referring to the holding arm component 320, it is observed that the holding arm component 320 comprises two or more separate arms 325. Each arm 325 has a proximal end 322 and a distal end 324. As noted, the distal end 322 represents a flange used to catch the shoulder 314 of the engagement pin 310 when the holding arm component 320 is in its latched position.

In addition, each arm 325 has a pivot hole 327. As noted above, each pivot hole 327 is dimensioned to receive a respective horizontal pin (not shown). The respective pins reside proximate a top 342 of the top housing 340. The horizontal pins allow the arms 325 to pivot inwardly and outwardly relative to the top housing 340.

The standing valve puller 300 next includes the sliding component 330. The sliding component 330 comprises a generally tubular body wherein splines 335 are placed radially around an outer diameter. As the name implies, the sliding component 330 is configured to move (or slide) longitudinally along the standing valve puller 300. Specifically, the splines 335 slide along channels 346 disposed along an inner diameter of the top housing 340. A central channel 346 is seen in FIG. 6B.

Next shown in FIG. 5 is the top housing 340. The top housing 340 is a tubular body comprising a proximal end 342 and a distal end 344. The proximal end 342 includes pivot holes 347 that receive the horizontal pivot pins. In the preferred embodiment, two horizontal pins are used, requiring two pairs of pivot holes 347 located on each side of the top housing 340. In this way, the two opposing arms 325 are pivotally supported.

The proximal end 342 of the top housing 340 defines a pair of slanted surfaces 343. The slanted surfaces 343 are dimensioned to receive the respective arms 325 when they are pivoted outwardly. Preferably, the arms 325 are biased to pivot outwardly through the use of respective springs (not shown).

The distal end 344 of the top housing 340 comprises a male threaded member. The male threads at the distal end 344 connect to a proximal end 372 of the bottom housing 370, described further below.

FIG. 5 next shows a twisting component 350. The twisting component 350 also represents a somewhat tubular body. The twisting component 350 comprises a proximal end 352 and a distal end 354. Along the tubular body of the twisting component 350 are longitudinal slots. The slots alternate between long slots and short slots (identified as slots 351 and 357, respectively, in FIG. 4B). Regardless of their length, the slots 351, 357 are dimensioned to slidably receive the splines 335 of the sliding component 330.

Next shown in FIG. 5 is the spring 360. The spring 360 resides within the bottom housing 370. The spring 360 is maintained in compression between a shoulder 382 (visible in FIG. 3B) of the threaded connector 380 and a corresponding shoulder 353 (also visible in FIG. 3B) of the twisting component 350. The spring 360 urges the twisting component 350 upward against the sliding component 330. Stated another way, the spring 360 is used to bias the twisting component 350 into engagement with the twisting component 330. The spring 360 is preferably fabricated from steel.

FIG. 5 next presents the bottom housing 370. As described above, the bottom housing 370 is a tubular body having a proximal end 372 and a distal end 374. The proximal end 372 comprises female threads configured to connect to the male threaded end 344 of the top housing 340. Similarly, the distal end 374 comprises female threads configured to connect to male threads at the proximal end 382 of the threaded connector 380.

It is noted that one or more holes 376 may be drilled into the bottom housing 370. This allows the standing valve puller 300 to be flushed out, either after the puller 300 has been retrieved to the surface, or in response to a hot oil treatment or chemical treatment wherein fluid is injected downhole.

Finally, FIG. 5 shows the threaded connector 380. The threaded connector 380 provides a means for connecting the standing valve puller 300 with the standing valve 960. The threaded connector 380 includes a distal end 384, discussed above in connection with FIG. 1.

In the view of FIG. 5, the threaded connector 380 is shown as a separate component from the bottom housing 370. However, it is understood that the threaded connector 380 may be integral to the bottom housing 370, meaning that the distal end of the housing 370 is actually the threaded male tip 384.

FIG. 6A is a side view of the standing valve puller 300 of FIG. 1. The tubular housing is shown, with the top housing 340 and bottom housing 370 being connected. In addition, the flanges 322 of the arms 325 are shown extending up from the top housing 340.

Also visible in FIG. 6A is the engagement pin 310. It can be seen that the shoulder 314 of the engagement pin has engaged the flanges 322 from underneath. This indicates that the engagement pin 310 is being pulled upward.

FIG. 6B is a cross-sectional view of the standing valve puller 300 and the engagement pin 310 of FIG. 6A. The view is taken across Line B-B of FIG. 6A. In this view, the standing valve puller 300 is in a latched position, enabling the shoulder 314 of the engagement pin 310 to “catch” the flanges 322 of the respective arms 325 and pull the standing valve puller 300 and connected standing valve 164 up from a wellbore 100.

Of interest, FIG. 6B shows the spring 360 residing between the shoulder 383 of the threaded connector 380 and the shoulder 353 of the twisting component 350. Here, the spring 360 is not being compressed. The interrelationship between a distal end 334 of the sliding component 330 and a proximal end 352 of the twisting component 350 can also be inferred. When the sliding component 330 is pushed down through the channels 346 in the top housing 340, the toothed profile of the distal end 334 of the sliding component 330 will engage the mating toothed profile of the proximal end 352 of the twisting component 350. This will induce a rotation of the twisting component 350, which radially advances the slots 355 of the twisting component 350 from long 357 to short 351 to long 357, and so forth. In one aspect, a lower end of each of the splines 335 is angled, such as at 45-degrees, to urge rotation of the twisting component 350 when the twisting component 350 is acted upon by the sliding component 330.

As the sliding component 330 is forced downward by the engagement pin 310, it will rotate the twisting component 350 into a next position. In the latched position, the sliding component 330 will be forced upwards from the twisting component 350 into the holding arm component 320, under the force of the spring 360 as shown in FIG. 3B. This prevents the arms 325 from pivoting outwardly into the slanted surfaces 342. In the disengaged, or released, position the sliding component 330 will be in a “floating” position. This position will allow the arms 325 of the holding arm component 320 to freely pivot. This further allows the arms 325 to pivot outwardly into the slanted surfaces 342.

It is observed that the downward force of the shoulder 314 of the engagement pin 310 against the sliding component 330 will cause the distal end 334 of the sliding component 330 to engage the proximal end 352 of the twisting component 350. Where the splines 335 of the sliding component engage the long slots 357 (seen in FIG. 7B), the spring 360 will force the twisting component 350 upwards along the top housing 340. At the same time, the sliding component is prevented from twisting because the splines 335 reside in the channels 346 along the inner diameter of the top housing 340.

FIG. 7A is another perspective view of the standing valve puller 300 of FIG. 5. Components of the standing valve puller 300 are partially exploded apart for illustrative purposes. Here, the engagement pin 310 is not shown. Also visible are two of the pivot holes 347 in the top housing 340.

One or more holes 346 may be drilled into the top housing 340, serving as drain holes. The drain holes 346 allow fluids to drain from the puller 300 when the standing valve 164 is being pulled from a wellbore.

FIG. 7B is a side view of the more-fully exploded-apart components of the standing valve puller 300 of FIG. 7A. Of interest, it can be seen that the arms 325 of the holding arm component 320 are independent (not connected) pieces that are able to pivot separately.

FIG. 8 is a cross-sectional view of the standing valve puller 300 of FIG. 5. The engagement pin 310 again is not shown. One of the arms 325 is visible extending up from the top 342 of the top housing 340. It is observed that in FIG. 8, the spring 360 has been removed. The twisting component 350 is, for illustrative purposes, not being urged upwardly against the sliding component 330.

FIG. 9A is perspective view of the holding arm component 320. In this view, both arms 325 of the component 320 are presented. The arms 325 are pivoted inwardly for illustrative purposes. Of interest, through-openings 327 are shown through each of the legs 325 for receiving a pivot pin (not shown).

It is noted that the lower end 324 of each arm includes a beveled inward surface 329. The beveled inward surface 329 of each of the legs 325 accommodates the pivoting action of the legs 325, permitting the legs 325 to pivot outwardly more fully into the beveled upper surface 342. At the same time, the beveled surfaces 329 receive the shoulder 314 when the engagement pin 310 is moved downwardly into the standing valve puller 300.

An upper rear surface 321 of each arm 325 offers a curvilinear profile. This profile is intended to match the slope of the slanted surface 343, allowing the arms 325 to rest against the slanted surface 343 when the arms 325 pivot outwardly.

FIG. 9B is another perspective view of the holding arm component 320. Here, the holding arm component 320 is again in its latched position.

FIG. 10 is still another perspective view of the holding arm component 320. In this view, the individual arms 325 have been pivoted outward into their “released” position. An engagement pin 310 is positioned above the holding arm component 320, ready to move down through the central bore 305 and to depress the sliding component 330.

It is again understood that springs (not shown) may be placed behind the individual arms 325 in order to bias the arms 325 away from each other. This accommodates lowering of the engagement pin 310 through the central bore 305 and into the upper housing 330.

Returning to the flow chart of FIG. 2B, and particularly Box 260, it can be seen that the engagement pin 310 can be released from the standing valve puller 300 by applying a compressive force to the standing valve puller 300. This is done by slacking weight off of the rod string 124, directing gravitational force through the traveling valve 162, through the engagement pin 310, and into the standing valve puller 300. This will cause the arms 325 of the holding arm component 320 to release, that is to open up as shown in FIGS. 4 and 10.

To demonstrate operation of the releasable connection in the methods herein, FIGS. 11A through 11F are presented. Each figure presents a wellbore 1100 in a horizontal orientation. The wellbore 1100 may represent an enlarged portion of the wellbore 100 of FIG. 1, and particularly the horizontal section 146. However, in this view standard steel casing is used as the production casing, with the casing having been perforated before run-in.

The wellbore 1100 defines a cylindrical bore 1105 that has been drilled into an earth subsurface 110. The cylindrical bore 1105 is lined with a series of steel casings, with each string of casing having a progressively smaller outer diameter. In FIGS. 11A-11F, only the lowermost string of casing is shown. This is referred to as a production casing 1110.

The production casing 1110 extends to proximate a lower end 1108 of the wellbore 1100. The casing 1110 is cemented into the formation 110 through a column of cement 1115. Specifically, the column of cement 1115 is squeezed into an annular area formed between the production casing 1110 and the surrounding earth formation 110. In addition, the casing 1110 and cement column 1115 have been perforated. Illustrative perforations are shown at 1125. The perforations 1125 allow reservoir fluids to flow into the wellbore 1100. It is understood that in an actual, horizontally-completed well, the casing 1110 will have multiple perforations, extending in some cases one to four miles.

After perforating, the formation 110 is typically acidized and/or fractured through the perforations 1125. Hydraulic fracturing consists of injecting water with friction reducers or viscous fluids (usually shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock parts and forms a network of fractures. The fracturing fluid is typically mixed with a proppant material such as sand, ceramic beads or other granular materials. The proppant serves to hold the fractures open after the hydraulic pressures are released. In the case of so-called “tight” or unconventional formations, the combination of fractures and injected proppant substantially increases the flow capacity, or permeability, of the treated reservoir.

Those of ordinary skill in the art will understand that the process of perforating and fracturing a well is done in multiple zones. The operator typically perfs and fracs a first zone at the end of the wellbore, then sets a plug above the perforations. The perforating guns are run back into the hole, and a next zone is perfed and fracked.

In FIG. 11A, the wellbore is indicated at 1100A. Here, a positive displacement pump is being run into the production casing 1110. Movement of the positive displacement pump into the wellbore is indicated at Arrow R₁. The positive displacement pump represents a traveling valve 1140 and a standing valve 1160. The traveling valve 1140 is disposed at the lower end of a sucker rod string 1130. The sucker rods in the string 1130 may be standard steel rods; alternatively, they may be fiberglass rods.

Those of ordinary skill in the art will understand that the traveling valve 140 is reciprocated up and down within the wellbore 1100 in response to movement of a prime mover at the surface (not shown). Such a prime mover may be, for example, a hydraulic pumping unit, a pneumatic pumping unit or a mechanical pumping unit. The present inventions are not limited by the manner in which the traveling valve 1140 is reciprocated.

Also seen in FIG. 11A is an engagement pin 310. The engagement pin 310 is secured to a lower end of the traveling valve 1140 by means of threads within the box connector 318. The engagement pin 310 will remain in the wellbore 1100 during production operations.

The engagement pin 310 is latched into a standing valve puller 300. This would be in accordance with the view of FIG. 3, discussed above. The standing valve puller 300 is threaded into the top of a standing valve 1160. This is done by means of threaded end 384.

The standing valve 1160 includes a ball 1167. The ball 1167 is part of a ball-and-seat arrangement as is well known in the art. However, in this arrangement the standing valve 1160 is retrofitted with an elastomeric band 1168 along the outer diameter. The band 1168 acts as a no-go landing nipple, and is configured to land in a corresponding seat 1118. The band 1168 may be supported by metal rings and serves the function of a so-called pump barrel. In this case, the elastomeric band 1168 is enlarged to mate with the seat 1118 within the production casing 1110.

As an alternative, a standard landing nipple may be used in the pump barrel that is part of the standing valve 1160. In that case, a modified seating nipple is employed. Such an arrangement is shown and discussed below in connection with FIG. 12. In either arrangement, the production tubing is not present and does not extend down to the horizontal section of the wellbore 1100.

The seat 1118 resides along the inner diameter of the production casing 1110. The seat 1118 acts as an internal constriction, or “seating nipple,” limiting downward movement of the standing valve 1160. The enlarged elastomeric seal ring 1168 on the outer body of the standing valve (or pump barrel) also forms a leak proof seal between the standing valve 1160 and the seating nipple 1118.

Of interest, the standing valve puller 300 will remain connected to the standing valve 1160 while the standing valve 1160 is fixed downhole on the seating nipple 1118 during production operations. In addition, the operator may adjust the location of the polished rod relative to the pumping unit at the surface, and then land the engagement pin 310 back into the standing valve puller 300. In this way, the standing valve 1160 may be unseated from the production casing 1110 without pulling the rod string from the wellbore 1100. Optionally, the standing valve 1160 may then be raised up the wellbore 1100 and replaced or serviced.

FIG. 11B is a next side view of the wellbore 1100. This is indicated at 1100B. In this view, the traveling valve 1140 and the standing valve 1160 have been moved further down the wellbore 1100B. This is again shown by Arrow RI. The elastomeric band 1168 has now landed in the seating nipple 1118. Note that the standing valve 1160 is fixed directly into the production casing 1110 with no production tubing. The standing valve 1160 is landed into the casing 1110 above the perforations 1125.

FIG. 11C is a next side view of the wellbore 1100. This is indicated at wellbore designation 1100C. In this view, a second compressive force is applied through the rod string 1130. This is shown at R_(C). The rod string 1130 is connected to the traveling valve 1140 through a connector 1135. The compressive force moves through the connector 1135, through the traveling valve 1140, and through the engagement pin 310 to unlatch from the standing valve puller 300.

In FIG. 11C, the standing valve 1160 includes a modified tubing barrel 1165. The elastomeric band 1168 extending from the tubing barrel 1165 remains landed in the seating nipple 1118.

FIG. 11D is a next side view of the wellbore 1100. This is indicated at wellbore designation 1100D. In this view, the traveling valve 1140 and connected engagement pin 310 having been released from the standing valve puller 300. The traveling valve 1140 has been repositioned in the wellbore 1100D above the standing valve 1160. The well is now ready for production.

FIG. 11E shows the traveling valve 1140 being lifted within the production casing 1110 by the sucker rod string 1130. This is indicated at wellbore designation 1100E. The upward action of the rod string 1130 causes a ball 1147 in the traveling valve 1140 to seat. This, in turn, allows the traveling valve 1140 to raise production fluids up the casing 1110 and to a well head and fluid separation equipment (not shown) at the surface. Arrow Ru indicates upward movement of the rod string 1130 and connected traveling valve 1140. Arrow P indicates an in-flow of production fluids into the wellbore 1100E.

FIG. 11E also shows that the standing valve 1160 remains affixed to the bottom of the casing 1110. As the traveling valve 1140 pushes production fluids up the casing 1110, negative pressure is created below the traveling valve 1140. This causes the ball 1167 associated with the standing valve 1160 to become unseated, which in turn pulls production fluids entering the wellbore 1100E into the standing valve 1160. The production fluids travel through ports in the standing valve 1160 and into the casing 1120 as shown by Arrow S.

Finally, FIG. 11F shows the traveling valve 1140 being lowered back down the production casing 1110 by the sucker rod string 1140. This is indicated at wellbore designation 1100F. Arrow R_(D) demonstrates the downward movement of the sucker rod string 1130. Downward movement of the connected traveling valve 1140 increases fluid pressure above the standing valve 1160, which causes the ball 1167 in the standing valve 1160 to seat.

FIG. 11F also shows that the ball 1147 in the traveling valve 1140 has unseated. This allows production fluids to pass through the traveling valve 1140, and to flow through ports and up the casing 1110. Arrow T indicates upward fluid movement through the traveling valve 1140.

Additional components and features of the standing valve puller 300 are described in U.S. Pat. No. 10,605,017 entitled “Unseating Tool for Downhole Standing Valve.” That patent is incorporated herein by reference herein. The novel standing valve puller of the '017 patent allows a service company to pull the standing valve at any time while the sucker rods and traveling valve are still in the wellbore. Alternatively, a pumper or service company at the wellsite can run the sucker rod string, the engagement pin, the standing valve puller and the standing valve into the wellbore together, and then release the traveling valve from the standing valve as shown in the FIG. 11 series of drawings, all in one trip.

Returning again to FIG. 2B, the method 200 additionally includes mechanically or operatively connecting a top end of the rod string to a polished rod. This is shown in Box 270. The polished rod is part of a pumping unit residing at the surface. In this way, the rod string extends from the surface, down into a vertical section of the wellbore, across a transitional section of the wellbore, and into the production casing residing along the horizontal section of the wellbore.

It is understood that the operator will manually adjust a location at which a harness and clamps supporting the polished rod is secured to the polished rod itself. This ensures that the traveling valve will be appropriately spaced above the standing valve. Thus, Box 270 of the method 200 also includes adjusting a position of the polished rod relative to the pumping system. Specifically, clamps associated with the pumping rod system are moved up the polished rod. The step of Box 220A enables the sucker rod string and connected traveling valve to travel lower into the production tubing on a down stroke.

The polished rod is part of a pumping unit, which resides at the surface. The pumping unit may be either a mechanical pumping unit such as a so-called rod beam (or sometimes “rocking beam”) unit. Alternatively, the pumping unit may be a linear pumping unit that uses hydraulic fluid or pneumatic fluid to cyclically act against a piston within a cylinder. In either instance, the pumping unit will use clamps and a harness to secure the pumping unit to the polished rod and to produce reciprocating motion of the downhole traveling valve above the standing valve.

Finally, the method may comprise producing hydrocarbon fluids from the production casing using the fluid pumping system. This is offered in Box 280. Note that no production tubing need be placed within the wellbore. Of course, a production string with a packer may optionally be installed into the vertical section of the well to provide a beneficial pressure differential. However, the rod string will extend well beyond the packer and into the horizontal section of the well.

The pumping unit will provide an upstroke and a down stroke. The speed at which the upstroke and the down stroke take place may be preset by the operator and periodically adjusted. Alternatively, the speeds may be adjusted by a rod pump controller located at the well head in response to real time load cell readings or manual override settings. Rod pump controllers will have override minimum speed and maximum speed settings.

As noted, the horizontal wellbore 1100 shown in the FIG. 11 series of drawings is completed with production casing. However, a wellbore may be completed using slotted liner. In one aspect of the methods herein, the fluids are produced from the pay zone through a sand screen. In this instance, the method will include running the sand screen into the horizontal leg of the wellbore using a working string. Preferably, a packer is placed between the end of the working string and the top end of the sand screen.

The method next includes setting the packer along the horizontal section of the wellbore. This may be done, for example, by operating a J-slot mechanism associated with the packer. The J-slot mechanism allows the packer to be set through a cycling mechanism, wherein the cycling takes place in response to compressive force applied by the working string through pins, or tabs. Preferably, the compressive force is a mechanical force applied by letting the weight down off of the working string. Thus, in one aspect the method 200 includes operating a J-slot mechanism to set the packer in the wellbore.

Once the packer is set, the method includes disconnecting the running string from the packer. This again may comprise operating the J-slot mechanism by applying a compressive force through the working string and against the J-slot mechanism to release the working string from the packer. The working string is then removed from the wellbore.

This is all done before the fluid pumping system is run into the wellbore (Box 240) and the standing valve is landed in a seating nipple (Box 250).

FIG. 12 is a cross-sectional view of a wellbore 1200 having received a pumping system. The pumping system includes a sucker rod string 1130, a traveling valve 1140, and a standing valve 1160. The traveling valve 1140 and the standing valve 1160 each represents a ball-and-seat valve, wherein traveling valve 1140 includes ball 1147 while standing valve 1160 includes ball 1167.

As with wellbore 1100, wellbore 1200 represents a horizontal section, with a string of production casing 1110 placed within a cylindrical borehole 1105. However, in lieu of perforations 1125, wellbore 1200 utilizes joints of tubular bodies 1220 having slots 1205. The tubular bodies 1220 may represent joints of sand screen. Alternatively, the tubular bodies 1220 may represent joints of slotted liner. In either instance, it is understood that multiple joints of slotted tubular bodies 1220 may be employed, extending one or even two or three miles along the horizontal wellbore 1200. The tubular bodies 1200 extend to a lower end of the wellbore 1108.

The standing valve 1160 includes a standard tubing barrel 1165. The tubing barrel 1165 includes an elastomeric band 1163. The elastomeric band 1263 serves as a so-called tubing plunger and is configured to land onto a modified seating nipple 1260. The seating nipple 1260 comprises a metal member 1263 that extends into a bore 1205, that receives the elastomeric band 1163 to form the fluid seal.

It is noted that the seating nipple 1260 resides in the wellbore 1200 above the slotted tubular bodies 1200. It is further noted that no column of cement is placed between the slotted tubular bodies 1200 and the borehole 1105. To ensure that wellbore fluids enter the bore 1205 and are pumped to the surface 105, a packer 1230 may be placed above the tubular bodies 1200. The packer 1230 will include an elastomeric element 1235. The elastomeric element 1205 is actuated into engagement with the surrounding bore 1105 using a setting tool (not shown).

In the arrangement of FIG. 12, the slotted tubular bodies 1220 (in this case, joints of slotted liner) are not run into the wellbore on a working string; rather, they are run into the wellbore 1200 as part of a continuous threaded string with the production casing 1110. The packer 1230 is part of the continuous threaded pipe string. Setting the sealing element 1235 of the packer 1230 in the wellbore means expanding the sealing element 1235 into engagement with the surrounding borehole 1105. In this instance, the packer may be an expandable packer that is actuated when placed in contact with hydrocarbon or other fluids.

The wellbore arrangements shown in the FIG. 11 series of drawings an in FIG. 12 show ball-and-seat valves for both the traveling valve 1140 and the standing valve 1160. It is understood that other valve arrangements may be employed for one or both of the valves. For example, due to the horizontal incline of the wellbores, the operator may prefer to use mechanical valves. The present methods are not limited by the type of valves used for the artificial lift unless so stated in the claims.

Further, variations of the method of producing hydrocarbon fluids from a wellbore may fall within the spirit of the claims, below. It will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof. 

I claim:
 1. A method of producing hydrocarbon fluids from a wellbore, comprising: providing a wellbore, the wellbore having been completed with a horizontal section; running a fluid pumping system into the wellbore, the fluid pumping system comprising: a sucker rod string, a traveling valve residing at a lower end of the sucker rod string, and a standing valve releasably connected to a lower end of the traveling valve; landing the standing valve into a seating nipple along the horizontal section of the wellbore; releasing the standing valve from the traveling valve while the fluid pumping system is in the wellbore; and operating a pumping unit at a surface to reciprocate the sucker rod string and traveling valve, and to produce hydrocarbon fluids from the production casing.
 2. The method of claim 1, wherein the horizontal section of the wellbore comprises: at least one joint of production casing; a plurality of slotted tubular bodies; and a packer placed between the at least one joint of production casing and the plurality of slotted tubular bodies, such that when the packer is set, an elastomeric element seals an annular region between the production casing and an inner bore of the slotted tubular bodies, ensuring upward flow of production fluids through the casing en route to the surface; and wherein the seating nipple resides above the slotted tubular bodies.
 3. The method of claim 2, wherein the slotted tubular bodies comprise joints of sand screen or joints of slotted liner.
 4. The method of claim 1, wherein the horizontal section of the wellbore comprises: a string of production casing cemented into the wellbore; and a plurality of perforations placed along the string of production casing; and wherein the seating nipple resides above the perforations.
 5. The method of claim 1, wherein: the wellbore does not have a string of production tubing therein; and the sucker rod string extends into and reciprocates within the horizontal section of the wellbore.
 6. The method of claim 1, wherein: the horizontal section of the wellbore does not have a string of production tubing therein; and the sucker rod string extends into and reciprocates within the horizontal section of the wellbore.
 7. The method of claim 1, wherein releasing the standing valve from the traveling valve comprises applying a compressive force through the working string and against the releasable connection, and then pulling the rod string and connected traveling valve up from the standing valve, but without pulling the rod string to a surface.
 8. The method of claim 7, wherein the releasable connection comprises: a tubular housing comprising a proximal end and a distal end, and a bore there along; a connector at the distal end of the tubular housing connected to the standing valve; and a holding arm component comprising at least two arms, wherein each of the at least two arms is configured to pivot at the proximal end of the tubular housing such that when an engagement pin located at a lower end of the traveling valve moves into the bore a first time, the arms pivot inwardly into a latched position and latch onto a shoulder of the engagement pin, but when the engagement pin moves into the bore a second time, the arms pivot outwardly to a released position and release the shoulder of the engagement pin.
 9. The method of claim 8, wherein the releasable connection further comprises: a spring residing within the bore of the tubular housing and abutting the connector; and a sliding component configured to move along the bore of the tubular housing in response to a downward force applied by the engagement pin, wherein: the sliding component includes a series of splines residing radially around an outer diameter of the sliding component; and downward movement of the engagement pin urges the sliding component to move downward within the tubular housing.
 10. The method of claim 4, further comprising: operatively connecting a top end of the rod string to a polished rod at the surface, wherein the polished rod is associated with the pumping unit.
 11. The method of claim 10, further comprising: adjusting a location at which a harness is secured to the polished rod by clamps in order to appropriately space the traveling valve above the standing valve.
 12. The method of claim 10, wherein the sucker rod string comprises one or more friction reducer couplings along a transition section of the wellbore.
 13. The method of claim 1, further comprising: running a sand screen and connected packer into the wellbore using a working string, wherein the sand screen is operatively connected to a lower end of the packer; and setting the packer inside of a joint of production casing along the horizontal section of the wellbore; wherein the sand screen comprises the casing.
 14. The method of claim 13, wherein: the packer comprises a J-slot mechanism; and setting the packer comprises operating the J-slot mechanism by applying a compressive force through the working string and against the J-slot mechanism.
 15. The method of claim 14, wherein: the working string is a string of coiled tubing; the sand screen and connected packer are run into the wellbore before the fluid pumping system is run into the wellbore; and the method further comprises: releasing the coiled tubing from the packer after the packer has been set; and pulling the coiled tubing from the wellbore.
 16. The method of claim 11, wherein releasing the standing valve from the traveling valve comprises applying a compressive force through the working string and against the releasable connection, and then pulling the rod string and connected traveling valve up from the standing valve, but without pulling the rod string to a surface.
 17. The method of claim 13, wherein the packer is set using a wireline. 